EP2287438B1 - Vorrichtung und Verfahren zur Rückgewinnung der unterirdischen Flüssigkeiten und/oder Injizieren von Flüssigkeiten und/oder Injizieren von Flüssigkeiten in einem Bohrloch - Google Patents

Vorrichtung und Verfahren zur Rückgewinnung der unterirdischen Flüssigkeiten und/oder Injizieren von Flüssigkeiten und/oder Injizieren von Flüssigkeiten in einem Bohrloch Download PDF

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Publication number
EP2287438B1
EP2287438B1 EP10013192.9A EP10013192A EP2287438B1 EP 2287438 B1 EP2287438 B1 EP 2287438B1 EP 10013192 A EP10013192 A EP 10013192A EP 2287438 B1 EP2287438 B1 EP 2287438B1
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EP
European Patent Office
Prior art keywords
fluids
bore
production
conduit
well
Prior art date
Legal status (The legal status is an assumption and is not a legal conclusion. Google has not performed a legal analysis and makes no representation as to the accuracy of the status listed.)
Expired - Lifetime
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EP10013192.9A
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English (en)
French (fr)
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EP2287438A1 (de
Inventor
Ian Donald
John Reid
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OneSubsea IP UK Ltd
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OneSubsea IP UK Ltd
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Priority claimed from GBGB0312543.2A external-priority patent/GB0312543D0/en
Priority claimed from US10/651,703 external-priority patent/US7111687B2/en
Priority claimed from GBGB0405471.4A external-priority patent/GB0405471D0/en
Priority claimed from GBGB0405454.0A external-priority patent/GB0405454D0/en
Application filed by OneSubsea IP UK Ltd filed Critical OneSubsea IP UK Ltd
Publication of EP2287438A1 publication Critical patent/EP2287438A1/de
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Classifications

    • E—FIXED CONSTRUCTIONS
    • E21—EARTH OR ROCK DRILLING; MINING
    • E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
    • E21B33/00—Sealing or packing boreholes or wells
    • E21B33/02—Surface sealing or packing
    • E21B33/03—Well heads; Setting-up thereof
    • E21B33/035—Well heads; Setting-up thereof specially adapted for underwater installations
    • E21B33/0353—Horizontal or spool trees, i.e. without production valves in the vertical main bore
    • E—FIXED CONSTRUCTIONS
    • E21—EARTH OR ROCK DRILLING; MINING
    • E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
    • E21B33/00—Sealing or packing boreholes or wells
    • E21B33/02—Surface sealing or packing
    • E21B33/03—Well heads; Setting-up thereof
    • E21B33/035—Well heads; Setting-up thereof specially adapted for underwater installations
    • E21B33/0387—Hydraulic stab connectors
    • E—FIXED CONSTRUCTIONS
    • E21—EARTH OR ROCK DRILLING; MINING
    • E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
    • E21B33/00—Sealing or packing boreholes or wells
    • E21B33/02—Surface sealing or packing
    • E21B33/03—Well heads; Setting-up thereof
    • E—FIXED CONSTRUCTIONS
    • E21—EARTH OR ROCK DRILLING; MINING
    • E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
    • E21B33/00—Sealing or packing boreholes or wells
    • E21B33/02—Surface sealing or packing
    • E21B33/03—Well heads; Setting-up thereof
    • E21B33/04—Casing heads; Suspending casings or tubings in well heads
    • E21B33/047—Casing heads; Suspending casings or tubings in well heads for plural tubing strings
    • E—FIXED CONSTRUCTIONS
    • E21—EARTH OR ROCK DRILLING; MINING
    • E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
    • E21B33/00—Sealing or packing boreholes or wells
    • E21B33/02—Surface sealing or packing
    • E21B33/03—Well heads; Setting-up thereof
    • E21B33/068—Well heads; Setting-up thereof having provision for introducing objects or fluids into, or removing objects from, wells
    • E—FIXED CONSTRUCTIONS
    • E21—EARTH OR ROCK DRILLING; MINING
    • E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
    • E21B33/00—Sealing or packing boreholes or wells
    • E21B33/02—Surface sealing or packing
    • E21B33/03—Well heads; Setting-up thereof
    • E21B33/068—Well heads; Setting-up thereof having provision for introducing objects or fluids into, or removing objects from, wells
    • E21B33/076—Well heads; Setting-up thereof having provision for introducing objects or fluids into, or removing objects from, wells specially adapted for underwater installations
    • E—FIXED CONSTRUCTIONS
    • E21—EARTH OR ROCK DRILLING; MINING
    • E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
    • E21B34/00—Valve arrangements for boreholes or wells
    • E21B34/02—Valve arrangements for boreholes or wells in well heads
    • E21B34/025—Chokes or valves in wellheads and sub-sea wellheads for variably regulating fluid flow
    • E—FIXED CONSTRUCTIONS
    • E21—EARTH OR ROCK DRILLING; MINING
    • E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
    • E21B41/00—Equipment or details not covered by groups E21B15/00 - E21B40/00
    • E21B41/0007—Equipment or details not covered by groups E21B15/00 - E21B40/00 for underwater installations
    • E—FIXED CONSTRUCTIONS
    • E21—EARTH OR ROCK DRILLING; MINING
    • E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
    • E21B43/00—Methods or apparatus for obtaining oil, gas, water, soluble or meltable materials or a slurry of minerals from wells
    • E21B43/01—Methods or apparatus for obtaining oil, gas, water, soluble or meltable materials or a slurry of minerals from wells specially adapted for obtaining from underwater installations
    • E—FIXED CONSTRUCTIONS
    • E21—EARTH OR ROCK DRILLING; MINING
    • E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
    • E21B43/00—Methods or apparatus for obtaining oil, gas, water, soluble or meltable materials or a slurry of minerals from wells
    • E21B43/12—Methods or apparatus for controlling the flow of the obtained fluid to or in wells
    • E—FIXED CONSTRUCTIONS
    • E21—EARTH OR ROCK DRILLING; MINING
    • E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
    • E21B43/00—Methods or apparatus for obtaining oil, gas, water, soluble or meltable materials or a slurry of minerals from wells
    • E21B43/16—Enhanced recovery methods for obtaining hydrocarbons
    • E—FIXED CONSTRUCTIONS
    • E21—EARTH OR ROCK DRILLING; MINING
    • E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
    • E21B43/00—Methods or apparatus for obtaining oil, gas, water, soluble or meltable materials or a slurry of minerals from wells
    • E21B43/16—Enhanced recovery methods for obtaining hydrocarbons
    • E21B43/162—Injecting fluid from longitudinally spaced locations in injection well
    • E—FIXED CONSTRUCTIONS
    • E21—EARTH OR ROCK DRILLING; MINING
    • E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
    • E21B43/00—Methods or apparatus for obtaining oil, gas, water, soluble or meltable materials or a slurry of minerals from wells
    • E21B43/16—Enhanced recovery methods for obtaining hydrocarbons
    • E21B43/166—Injecting a gaseous medium; Injecting a gaseous medium and a liquid medium
    • E—FIXED CONSTRUCTIONS
    • E21—EARTH OR ROCK DRILLING; MINING
    • E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
    • E21B43/00—Methods or apparatus for obtaining oil, gas, water, soluble or meltable materials or a slurry of minerals from wells
    • E21B43/34—Arrangements for separating materials produced by the well
    • E21B43/36—Underwater separating arrangements
    • E—FIXED CONSTRUCTIONS
    • E21—EARTH OR ROCK DRILLING; MINING
    • E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
    • E21B34/00—Valve arrangements for boreholes or wells
    • E21B34/02—Valve arrangements for boreholes or wells in well heads
    • E21B34/04—Valve arrangements for boreholes or wells in well heads in underwater well heads

Definitions

  • the present invention relates to apparatus and methods for diverting fluids.
  • Embodiments of the invention can be used for recovery and injection. Some embodiments relate especially but not exclusively to recovery and injection, into either the same, or a different well.
  • Christmas trees are well known in the art of oil and gas wells, and generally comprise an assembly of pipes, valves and fittings installed in a wellhead after completion of drilling and installation of the production tubing to control the flow of oil and gas from the well.
  • Subsea christmas trees typically have at least two bores one of which communicates with the production tubing (the production bore), and the other of which communicates with the annulus (the annulus bore).
  • Typical designs of christmas tree have a side outlet (a production wing branch) to the production bore closed by a production wing valve for removal of production fluids from the production bore.
  • the annulus bore also typically has an annulus wing branch with a respective annulus wing valve.
  • the top of the production bore and the top of the annulus bore are usually capped by a christmas tree cap which typically seals off the various bores in the christmas tree, and provides hydraulic channels for operation of the various valves in the christmas tree by means of intervention equipment, or remotely from an offshore installation.
  • a further alternative is to pressure boost the production fluids by installing a pump from a rig, but this requires a well intervention from the rig, which can be even more expensive than breaking the subsea or seabed pipework.
  • WO02/38912 discloses an earlier design of diverter assembly, over which the present invention is characterised.
  • a diverter assembly for an oil or gas well according to claim 1.
  • the oil or gas well is typically a subsea well but the invention is equally applicable to topside wells.
  • wing branch we mean any branch of the tree, other than a production bore of a tree.
  • the wing branch can be a production or an annulus wing branch connected to a production bore or an annulus bore respectively.
  • the diverter assembly is attached to a choke body.
  • "Choke body” can mean the housing which remains after the tree's standard choke has been removed.
  • the diverter assembly could be located in a branch in series with a choke.
  • the diverter assembly could be located between the choke and the production wing valve or between the choke and the branch outlet.
  • Further alternative embodiments could have the diverter assembly located in pipework coupled to the tree, instead of within the tree itself. Such embodiments allow the diverter assembly to be used in addition to a choke, instead of replacing the choke.
  • Embodiments where the diverter assembly is adapted to connect to a branch of a tree means that the tree cap does not have to be removed to fit the diverter assembly.
  • Embodiments of the invention can be easily retro-fitted to existing trees.
  • the diverter assembly is locatable within a bore in the branch of the tree.
  • the internal passage of the diverter assembly is in communication with the interior of the choke body, or other part of the tree branch.
  • Embodiments of the invention provide the advantage that fluids can be diverted from their usual path between the well bore and the outlet of the wing branch.
  • the fluids may be produced fluids being recovered and travelling from the well bore to the outlet of a tree.
  • the fluids may be injection fluids travelling in the reverse direction into the well bore.
  • the choke is standard equipment, there are well-known and safe techniques of removing and replacing the choke as it wears out. The same tried and tested techniques can be used to remove the choke from the choke body and to clamp the diverter assembly onto the choke body, without the risk of leaking well fluids into the ocean. This enables new pipe work to be connected to the choke body and hence enables safe rerouting of the produced fluids, without having to undertake the considerable risk of disconnecting and reconnecting any of the existing pipes (e.g. the outlet header).
  • the choke body may be a production choke body or an annulus choke body.
  • a first end of the diverter assembly is provided with a clamp for attachment to a choke body or other part of the manifold branch.
  • the diverter assembly is cylindrical and has an internal passage extending axially between opposite ends of the diverter assembly.
  • one end of the internal passage is in a side of the diverter assembly.
  • the diverter assembly includes separation means to provide two separate regions within the diverter assembly.
  • each of these regions has a respective inlet and outlet so that fluid can flow through both of these regions independently.
  • the diverter assembly includes an axial insert portion.
  • the axial insert portion is in the form of a conduit.
  • the end of the conduit extends beyond the end of the housing of the diverter assembly.
  • the conduit divides the internal passage into a first region comprising the bore of the conduit and a second region comprising the annulus between the housing and the conduit.
  • the conduit is adapted to seal within the inside of the branch (e.g. inside the choke body) to prevent fluid communication between the annulus and the bore of the conduit.
  • the housing includes an axial insert portion in the form of a stem.
  • the axial insert portion is provided with a plug adapted to block an outlet of the christmas tree, or other kind of manifold.
  • the plug is adapted to fit within and seal inside a passage leading to an outlet of a branch of the manifold.
  • the diverter assembly provides means for diverting fluids from a first portion of a first flowpath to a second flowpath, and means for diverting the fluids from a second flowpath to a second portion of a first flowpath.
  • At least a part of the first flowpath comprises a branch of the manifold.
  • the first and second portions of the first flowpath could comprise the bore and the annulus of a conduit.
  • the diverter assembly is attached to the branch so that the internal passage of the diverter assembly is in communication with the interior of the branch.
  • a region defined by the diverter assembly is separate from the production bore of the well.
  • the internal passage of the diverter assembly is separated from the well bore by a closed valve in the tree.
  • the diverter assembly is provided with an insert in the form of a conduit which defines a first region comprising the bore of the conduit, and a second separate region comprising the annulus between the conduit and the housing.
  • one end of the conduit is sealed inside the choke body or other part of the branch, to prevent fluid communication between the first and second regions.
  • the annulus between the conduit and the diverter assembly is closed so that the annulus is in communication with the branch only.
  • the annulus has an outlet for connection to further pipes, so that the second region provides a flowpath which is separate from the first region formed by the bore of the conduit.
  • the first and second regions are connected by pipework.
  • the processing apparatus is connected in the pipework so that fluids are processed whilst passing through the connecting pipework.
  • the processing apparatus is chosen from at least one of: a pump; a process fluid turbine; injection apparatus for injecting gas or steam; chemical injection apparatus; a fluid riser; measurement apparatus; temperature measurement apparatus; flow rate measurement apparatus; constitution measurement apparatus; consistency measurement apparatus; gas separation apparatus; water separation apparatus; solids separation apparatus; and hydrocarbon separation apparatus.
  • the diverter assembly provides a barrier to separate a branch outlet from a branch inlet.
  • the barrier may separate a branch outlet from a production bore of a tree.
  • the barrier comprises a plug, which is typically located inside the choke body (or other part of the manifold branch) to block the branch outlet.
  • the plug is attached to the diverter assembly by a stem which extends axially through the internal passage of the diverter assembly.
  • the barrier comprises a conduit of the diverter assembly which is engaged within the choke body or other part of the branch.
  • the tree is provided with a conduit connecting the first and second regions.
  • a first set of fluids are recovered from a first well via a first diverter assembly and combined with other fluids in a communal conduit, and the combined fluids are then diverted into an export line via a second diverter assembly connected to a second well.
  • the diverter assembly is optionally located within a choke body; alternatively, the diverter assembly may be coupled in series with a choke.
  • the diverter assembly may be located in the tree branch adjacent to the choke, or it may be included within a separate extension portion of the tree branch.
  • the assembly is used for a method for recovering fluids from a well.
  • the assembly is used for a method for injecting fluids into a well.
  • the internal passage of the diverter assembly is in communication with the interior of the branch.
  • the fluids may be passed in either direction through the diverter assembly.
  • the diverter assembly includes separation means to provide two separate regions within the diverter assembly, and the method may includes the step of passing fluids through one or both of these regions.
  • fluids are passed through the first and the second regions in the same direction.
  • fluids are passed through the first and the second regions in opposite directions.
  • the fluids are passed through one of the first and second regions and subsequently at least a proportion of these fluids are then passed through the other of the first and the second regions.
  • the method includes the step of processing the fluids in the processing apparatus before passing the fluids back to the other of the first and second regions.
  • fluids may be passed through only one of the two separate regions.
  • the diverter assembly could be used to provide a connection between two flow paths which are unconnected to the well bore, e.g. between two external fluid lines.
  • fluids could flow only through a region which is sealed from the branch.
  • a flowpath could connect the bore of the conduit to a well bore (production or annulus bore) or another main bore of the tree to bypass the branch. This flowpath could optionally link a region defined by the diverter assembly to a well bore via an aperture in the tree cap.
  • the first and second regions are connected by pipework.
  • the processing apparatus is connected in the pipework so that fluids are processed whilst passing through the connecting pipework.
  • the method includes the step of removing a choke from the choke body before attaching the diverter assembly to the choke body.
  • the first portion of the first flowpath is typically in communication with the production bore, and the second portion of the first flowpath is typically connected to a pipeline for carrying away the recovered fluids (e.g. to the surface).
  • the first portion of the first flowpath is typically connected to an external fluid line, and the second portion of the first flowpath is in communication with the annulus bore.
  • the flow directions may be reversed.
  • the method provides the advantage that fluids can be diverted (e.g. recovered or injected into the well, or even diverted from another route, bypassing the well completely) without having to remove and replace any pipes already attached to the manifold branch outlet (e.g. a production wing branch outlet).
  • manifold branch outlet e.g. a production wing branch outlet
  • the method includes the step of recovering fluids from a well and the step of injecting fluids into the well.
  • some of the recovered fluids are re-injected into the same well, or a different well.
  • the production fluids could be separated into hydrocarbons and water; the hydrocarbons being returned to the first flowpath for recovery therefrom, and the water being returned and injected into the same or a different well.
  • both of the steps of recovering fluids and injecting fluids include using respective flow diverter assemblies.
  • only one of the steps of recovering and injecting fluids includes using a diverter assembly.
  • a first diverter assembly is connected to a first branch of the tree and a second diverter assembly is connected to a second branch of the tree.
  • the first branch comprises a production wing branch and the second branch comprises an annulus wing branch.
  • a flowpath connects the first and second diverter assemblies.
  • first and second diverter assemblies blocks a passage in the tree between a bore of the tree and its respective outlet.
  • first bore comprises a production bore and the second bore comprises an annulus bore.
  • first and second diverter assemblies can be connected together to allow the unwanted parts of the produced fluids (e.g. water and sand) to be directly injected back into the well, instead of being pumped away with the hydrocarbons.
  • the unwanted materials can be extracted from the hydrocarbons substantially at the wellhead, which reduces the quantity of production fluids to be pumped away, thereby saving energy.
  • the first and second diverter assemblies can alternatively or additionally be used to connect to other kinds of processing apparatus (e.g. the types described with reference to other aspects of the invention), such as a booster pump, filter apparatus, chemical injection apparatus, etc. to allow adding or taking away of substances and adjustment of pressure to be carried out adjacent to the wellhead.
  • the first and second diverter assemblies enable processing to be performed on both fluids being recovered and fluids being injected. Preferred embodiments of the invention enable both recovery and injection to occur simultaneously in the same well.
  • the first and second diverter assemblies are connected to the processing apparatus.
  • a tubing system adapted to both recover and inject fluids is also provided.
  • the tubing system is adapted to simultaneously recover and inject fluids.
  • the method includes the steps of: blocking a passage in the tree between a bore of the tree and its respective branch outlet; diverting fluids recovered from the well out of the tree; and injecting fluids into the well; wherein neither the fluids being diverted out of the tree nor the fluids being injected travel through the branch outlet of the blocked passage.
  • the processing apparatus is coupled to the second flowpath.
  • the processing apparatus separates hydrocarbons from the rest of the produced fluids.
  • the non-hydrocarbon components of the produced fluids are diverted to the second diverter assembly to provide at least one component of the injection fluids.
  • At least one component of the injection fluids is provided by an external fluid line which is not connected to the production bore or to the first diverter assembly.
  • the method includes the step of diverting at least some of the injection fluids from a first portion of a first flowpath to a second flowpath and diverting the fluids from the second flowpath back to a second portion of the first flowpath for injection into the annulus bore of the well.
  • the steps of recovering fluids from the well and injecting fluids into the well are carried out simultaneously.
  • a first well is provided with a first diverter assembly; a second well is provided with a second diverter assembly; and a flowpath connects the first and second diverter assemblies.
  • each of the first and second wells has a tree having a respective bore and a respective outlet, and at least one of the diverter assemblies blocks a passage in the tree between its respective tree bore and its respective tree outlet.
  • an alternative outlet is provided, and the diverter assembly diverts fluids into a path leading to the alternative outlet.
  • At least one of the first and second diverter assemblies is located within the production bore of its respective tree.
  • at least one of the first and second diverter assemblies is connected to a wing branch of its respective tree.
  • the method includes diverting fluids from a first well to a second well via at least one tree; blocking a passage in the tree between a bore of the tree and a branch outlet of the tree; and diverting at least some of the fluids from the first well to the second well via a path not including the branch outlet of the blocked passage.
  • the at least one tree comprises a tree of the first well and the method includes the further step of returning a portion of the recovered fluids to the tree of the first well and thereafter recovering that portion of the recovered fluids from the outlet of the blocked passage.
  • the method includes recovery of fluids from, and injection of fluids into, a well having a tree; wherein at least one of the steps of recovery and injection includes diverting fluids from a first portion of a first flowpath to a second flowpath and diverting the fluids from the second flowpath to a second portion of the first flowpath.
  • recovery and injection is simultaneous.
  • some of the recovered fluids are re-injected into the well.
  • the method includes recovering fluids from a first well and reinjecting at least some of these recovered fluids into a second well, and the steps of diverting fluids from a first portion of a first flowpath to a second flowpath, and diverting at least some of these fluids from the second flowpath to a second portion of the first flowpath.
  • the fluids are recovered from the first well via a first diverter assembly, and wherein the fluids are re-injected into the second well via a second diverter assembly.
  • the method also includes the step of processing the production fluids in a processing apparatus connected between the first and second wells.
  • the method includes the further step of returning a portion of the recovered fluids to the first diverter assembly and thereafter recovering that portion of the recovered fluids via the first diverter assembly.
  • the method includes recovering fluids from, or injecting fluids into, a well, including the step of diverting the fluids between a well bore and a branch outlet whilst bypassing at least a portion of the branch.
  • Such embodiments are useful to divert fluids to a processing apparatus and then to return them to the wing branch outlet for recovery via a standard export line attached to the outlet.
  • the method is also useful if a wing branch valve gets stuck shut.
  • the fluids are diverted via the tree cap.
  • the method includes diverting fluids from a first portion of a first flowpath to a second flowpath and diverting the fluids from the second flowpath into a second portion of the first flowpath.
  • the diverter assembly may be locatable in a wide range of places, including, but not limited to: the production bore, the annulus bore, the production wing branch, the annulus wing branch, a production choke body, an annulus choke body, a tree cap or external conduits connected to the tree.
  • the first and second flowpaths could comprise some or all of any part of the tree.
  • the first flowpath is a production bore or production line, and the first portion of it is typically a lower part near to the wellhead.
  • the first flowpath comprises an annulus bore.
  • the second portion of the first flowpath is typically a downstream portion of the bore or line adjacent a branch outlet, although the first or second portions can be in the branch or outlet of the first flowpath.
  • the diversion of fluids from the first flowpath allows the treatment of the fluids (e.g. with chemicals) or pressure boosting for more efficient recovery before re-entry into the first flowpath.
  • the second flowpath is an annulus bore, or a conduit inserted into the first flowpath.
  • Other types of bore may optionally be used for the second flowpath instead of an annulus bore.
  • the flow diversion from the first flowpath to the second flowpath is achieved by a cap on the tree.
  • the cap contains a pump or treatment apparatus, but this can be provided separately, or in another part of the apparatus, and in most embodiments of this type, flow will be diverted via the cap to the pump etc and returned to the cap by way of tubing.
  • a connection typically in the form of a conduit is typically provided to transfer fluids between the first and second flowpaths.
  • the diverter assembly can be formed from high grade steels or other metals, using e.g. resilient or inflatable sealing means as required.
  • the assembly may include outlets for the first and second flowpaths, for diversion of the fluids to a pump or treatment assembly, or other processing apparatus as described in this application.
  • the assembly optionally comprises a conduit capable of insertion into the first flowpath, the assembly having sealing means capable of sealing the conduit against the wall of the production bore.
  • the conduit may provide a flow diverter through its central bore which typically leads to a christmas tree cap and the pump mentioned previously.
  • the seal effected between the conduit and the first flowpath prevents fluid from the first flowpath entering the annulus between the conduit and the production bore except as described hereinafter.
  • the fluid After passing through a typical booster pump, squeeze or scale chemical treatment apparatus, the fluid is diverted into the second flowpath and from there to a crossover back to the first flowpath and first flowpath outlet.
  • the assembly and method are typically suited for subsea production wells in normal mode or during well testing, but can also be used in subsea water injection wells, land based oil production injection wells, and geothermal wells.
  • the pump can be powered by high pressure water or by electricity which can be supplied direct from a fixed or floating offshore installation, or from a tethered buoy arrangement, or by high pressure gas from a local source.
  • the cap typically seals within christmas tree bores above the upper master valve. Seals between the cap and bores of the tree are optionally O-ring, inflatable, or typically metal-to-metal seals.
  • the cap can be retro-fitted very cost effectively with no disruption to existing pipework and minimal impact on control systems already in place.
  • the typical design of the flow diverters within the cap can vary with the design of tree, the number, size, and configuration of the diverter channels being matched with the production and annulus bores, and others as the case may be. This provides a way to isolate the pump from the production bore if needed, and also provides a bypass loop.
  • the cap is typically capable of retro-fitting to existing trees, and many include equivalent hydraulic fluid conduits for control of tree valves, and which match and co-operate with the conduits or other control elements of the tree to which the cap is being fitted.
  • the cap has outlets for production and annulus flow paths for diversion of fluids away from the cap.
  • a pump can be accommodated within a bore of the tree.
  • the tree is typically a subsea tree, such as a christmas tree, typically on a subsea well, but a topside tree (or other topside manifold) connected to a topside well could also be appropriate.
  • Horizontal or vertical trees are equally suitable for use of the invention.
  • the bore of the tree may be a production bore.
  • the diverter assembly and pump could be located in any bore of the tree, for example, in a wing branch bore.
  • the flow diverter typically incorporates diverter means to divert fluids flowing through the bore of the tree from a first portion of the bore, through the pump, and back to a second portion of the bore for recovery therefrom via an outlet, which is typically the production wing valve.
  • the first portion from which the fluids are initially diverted is typically the production bore/other bore/line of the well, and flow from this portion is typically diverted into a diverter conduit sealed within the bore.
  • Fluid is typically diverted through the bore of the diverter conduit, and after passing therethrough, and exiting the bore of the diverter conduit, typically passes through the annulus created between the diverter conduit and the bore or line.
  • the fluid passes through the pump internally of the tree, thereby minimising the external profile of the tree, and reducing the chances of damage to the pump.
  • the pump is typically powered by a motor, and the type of motor can be chosen from several different forms.
  • a hydraulic motor, a turbine motor or moineau motor can be driven by any well-known method, for example an electro-hydraulic power pack or similar power source, and can be connected, either directly or indirectly, to the pump.
  • the motor can be an electric motor, powered by a local power source or by a remote power source.
  • Certain embodiments of the present invention allow the construction of wellhead assemblies that can drive the fluid flow in different directions, simply by reversing the flow of the pump, although in some embodiments valves may need to be changed (e.g. reversed) depending on the design of the embodiment.
  • the diverter assembly typically includes a tree cap that can be retrofitted to existing designs of tree, and can integrally contain the pump and/or the motor to drive it.
  • the flow diverter typically also comprises a conduit capable of insertion into the bore, and may have sealing means capable of sealing the conduit against the wall of the bore.
  • the flow diverter typically seals within christmas tree production bores above an upper master valve in a conventional tree, or in the tubing hangar of a horizontal tree, and seals can be optionally O-ring, inflatable, elastomeric or metal to metal seals.
  • the cap or other parts of the flow diverter can comprise hydraulic fluid conduits.
  • the pump can optionally be sealed within the conduit.
  • the tree can have an integral pump located in a bore of the tree, and fluids can be diverted from a first portion of a bore of the tree through the pump and into a second portion of the bore.
  • the diverter assembly is sealed in a bore of the tree, and the diverter assembly comprises a separator which divides the bore of the tree into two separate regions, and extends through the tree bore and into the production zone of the well.
  • the at least one diverter assembly comprises a conduit and at least one seal; the conduit optionally comprises a gas injection line.
  • This invention may be used in conjunction with a further diverter assembly according to any other aspect of the invention, or with a diverter assembly in the form of a conduit which is sealed in the production bore.
  • Both diverter assemblies may comprise conduits; one conduit may be arranged concentrically within the other conduit to provide concentric, separate regions within the production bore.
  • the fluid diverter assembly is sealed in a bore of a tree to form two separate regions in the bore extending into the production zone of the well, and wherein fluids are injected into the well via one of the regions and recovered via the other of the regions.
  • the injection fluids are typically gases; the method may include the steps of blocking a flowpath between the bore of the tree and a production wing outlet and diverting the recovered fluids out of the tree along an alternative route.
  • the recovered fluids may be diverting the recovered fluids to the processing apparatus and returning at least some of these recovered fluids to the tree and recovering these fluids from a wing branch outlet.
  • the recovered fluids may undergo any of the processes described in this invention, and may be returned to the tree for recovery, or not, (e.g. they may be recovered from a fluid riser) according to any of the described methods and flowpaths.
  • a typical production manifold on an offshore oil or gas wellhead (which is not an embodiment of the invention, but is useful for understanding the embodiments described later) comprises a christmas tree with a production bore 1 leading from production tubing (not shown) and carrying production fluids from a perforated region of the production casing in a reservoir (not shown).
  • An annulus bore 2 leads to the annulus between the casing and the production tubing and a christmas tree cap 4 which seals off the production and annulus bores 1, 2, and provides a number of hydraulic control channels 3 by which a remote platform or intervention vessel can communicate with and operate the valves in the christmas tree.
  • the cap 4 is removable from the christmas tree in order to expose the production and annulus bores in the event that intervention is required and tools need to be inserted into the production or annulus bores 1, 2.
  • the flow of fluids through the production and annulus bores is governed by various valves shown in the typical tree of Fig. 1 .
  • the production bore 1 has a branch 10 which is closed by a production wing valve (PWV) 12.
  • a production swab valve (PSV) 15 closes the production bore 1 above the branch 10 and PWV 12.
  • Two lower valves UPMV 17 and LPMV 18 (which is optional) close the production bore 1 below the branch 10 and PWV 12.
  • a crossover port (XOV) 20 is provided in the production bore 1 which connects to the crossover port (XOV) 21 in annulus bore 2.
  • the annulus bore is closed by an annulus master valve (AMV) 25 below an annulus outlet 28 controlled by an annulus wing valve (AWV) 29, itself below crossover port 21.
  • AMV annulus master valve
  • AMV annulus wing valve
  • the crossover port 21 is closed by crossover valve 30.
  • An annulus swab valve 32 located above the crossover port 21 closes the upper end of the annulus bore 2.
  • All valves in the tree are typically hydraulically controlled (with the exception of LPMV 18 which may be mechanically controlled) by means of hydraulic control channels 3 passing through the cap 4 and the body of the tool or via hoses as required, in response to signals generated from the surface or from an intervention vessel.
  • LPMV 18 and UPMV 17 are opened, PSV 15 is closed, and PWV 12 is opened to open the branch 10 which leads to the pipeline (not shown). PSV 15 and ASV 32 are only opened if intervention is required.
  • a wellhead cap 40 has a hollow conduit 42 with metal, inflatable or resilient seals 43 at its lower end which can seal the outside of the conduit 42 against the inside walls of the production bore 1, diverting production fluids flowing in through branch 10 into the annulus between the conduit 42 and the production bore 1 and through the outlet 46.
  • Outlet 46 leads via tubing to a processing apparatus.
  • the processing apparatus could comprise a pump or process fluid turbine, for boosting the pressure of the fluid.
  • the processing apparatus could inject gas, steam, sea water, drill cuttings or waste material into the fluids.
  • the injection of gas could be advantageous, as it would give the fluids "lift", making them easier to pump.
  • the addition of steam has the effect of adding energy to the fluids.
  • Injecting sea water into a well could be useful to boost the formation pressure for recovery of hydrocarbons from the well, and to maintain the pressure in the underground formation against collapse. Also, injecting waste gases or drill cuttings etc into a well obviates the need to dispose of these at the surface, which can prove expensive and environmentally damaging.
  • the processing apparatus could also enable chemicals to be added to the fluids, e.g. viscosity moderators, which thin out the fluids, making them easier to pump, or pipe skin friction moderators, which minimise the friction between the fluids and the pipes.
  • chemicals which could be injected are surfactants, refrigerants, and well fracturing chemicals.
  • Processing apparatus could also comprise injection water electrolysis equipment. The chemicals/injected materials could be added via one or more additional input conduits.
  • an additional input conduit could be used to provide extra fluids to be injected.
  • An additional input conduit could, for example, originate from an inlet header (shown in Fig 13 ).
  • an additional outlet could lead to an outlet header (also shown in Fig 13 ) for recovery of fluids.
  • the processing apparatus could also comprise a fluid riser, which could provide an alternative route between the well bore and the surface. This could be very useful if, for example, the branch 10 becomes blocked.
  • processing apparatus could comprise separation equipment e.g. for separating gas, water, sand/debris and/or hydrocarbons.
  • separation equipment e.g. for separating gas, water, sand/debris and/or hydrocarbons.
  • the separated component(s) could be siphoned off via one or more additional process conduits.
  • the processing apparatus could alternatively or additionally include measurement apparatus, e.g. for measuring the temperature/ flow rate/ constitution/ consistency, etc. The temperature could then be compared to temperature readings taken from the bottom of the well to calculate the temperature change in produced fluids. Furthermore, the processing apparatus could include injection water electrolysis equipment.
  • the bore of conduit 42 can be closed by a cap service valve (CSV) 45 which is normally open but can close off an inlet 44 of the hollow bore of the conduit 42.
  • CSV cap service valve
  • the conduit bore and the inlet 46 can also have an optional crossover valve (COV) designated 50, and a tree cap adapter 51 in order to adapt the flow diverter channels in the tree cap 40 to a particular design of tree head.
  • COV crossover valve
  • Control channels 3 are mated with a cap controlling adapter 5 in order to allow continuity of electrical or hydraulic control functions from surface or an intervention vessel.
  • This system therefore provides a fluid diverter for use with a wellhead tree comprising a thin walled diverter conduit and a seal stack element connected to a modified christmas tree cap, sealing inside the production bore of the christmas tree typically above the hydraulic master valve, diverting flow through the conduit annulus, and the top of the christmas tree cap and tree cap valves to typically a pressure boosting device or chemical treatment apparatus, with the return flow routed via the tree cap to the bore of the diverter conduit and to the well bore.
  • the present invention can usefully be used in multiple well combinations, whereby a production well and an injection well are connected together via processing apparatus.
  • Processing apparatus can separate water/ gas/ oil / sand/ debris from the fluids produced from a production well and then inject one or more of these into an injection well. Separating fluids from one well and reinjecting into another well via subsea processing apparatus reduces the quantity of tubing, time and energy necessary compared to performing each function individually. Processing apparatus may also include a riser to the surface, for carrying the produced fluids or a separated component of these to the surface.
  • Tubing connects the processing apparatus back to an inlet of a wellhead cap of the production well.
  • the processing apparatus could also be used to inject gas into the separated hydrocarbons for lift and also for the injection of any desired chemicals such as scale or wax inhibitors.
  • the hydrocarbons are then returned via tubing to the inlet and flow from there into the annulus between the conduit and the bore in which it is disposed. As the annulus is sealed at the upper and lower ends, the fluids flow through the export line for recovery.
  • the horizontal line of an injection well can serve as an injection line (instead of an export line). Fluids to be injected can enter the injection line, from where they pass via the annulus between the conduit and the bore to the tree cap outlet and tubing into a processing apparatus.
  • the processing apparatus may include a pump, chemical injection device, and/or separating devices, etc.
  • processing apparatus includes a riser
  • this riser could be used to transport the processed produced fluids to the surface, instead of passing them back down into the christmas tree of the production bore again for recovery via export line.
  • the processing apparatus may include a water injection booster pump connected via tubing to an injection well, a production booster pump connected via tubing to a production well, and a water separator vessel, connected between the two wells via tubing. Pumps are powered by respective high voltage electricity power umbilicals.
  • produced fluids from a production well exit as previously described via conduit 42, outlet and tubing; the pressure of the fluids are boosted by a booster pump.
  • the produced fluids then pass into a separator vessel, which separates the hydrocarbons from the produced water.
  • the hydrocarbons are returned to the production well cap via tubing; from the cap, they are then directed via the annulus surrounding the conduit to the export line.
  • the separated water is transferred via tubing to the wellbore of the injection well via an inlet.
  • the separated water enters the injection well through the inlet, from where it passes directly into its conduit 42 and from there, into the production bore and the depths of the injection well.
  • additional fluids into the injection well.
  • This can be done by closing a valve in tubing to prevent any fluids from entering the injection well via the tubing.
  • these additional fluids can enter the injection well via an injection line (which was formerly the export line in previous embodiments). The rest of this procedure will follow that described above. Fluids entering the injection line pass up the annulus between conduit 42 and the wellbore, are diverted by the seals 43 (see Fig. 2 ) at the lower end of conduit 42 to travel up the annulus, and exit via an outlet. The fluids then pass along tubing, are pressure boosted by the booster pump and are returned via conduit to an inlet of the christmas tree. From here, the fluids pass through the inside of conduit 42 and directly into the wellbore and the depths of the well.
  • fluids are injected into the injection well from tubing (i.e. fluids separated from the produced fluids of production well) and from the injection line (i.e. any additional fluids) in sequence.
  • tubing i.e. fluids separated from the produced fluids of production well
  • injection line i.e. any additional fluids
  • tubing could combine at the inlet and the two separate lines of injected fluids could be injected into the well simultaneously.
  • the processing apparatus could comprise simply the water separator vessel, and not include the booster pumps.
  • Figs. 3 and 4 Two embodiments of the claimed invention are shown in Figs. 3 and 4 ; these embodiments are adapted for use in a traditional and horizontal tree respectively. These embodiments have a diverter assembly 502 located partially inside a christmas tree choke body 500. (The internal parts of the choke have been removed, just leaving choke body 500). Choke body 500 communicates with an interior bore of a perpendicular extension of branch 10.
  • Diverter assembly 502 comprises a housing 504, a conduit 542, an inlet 546 and an outlet 544.
  • Housing 504 is substantially cylindrical and has an axial passage 508 extending along its entire length and a connecting lateral passage adjacent to its upper end; the lateral passage leads to outlet 544.
  • the lower end of housing 504 is adapted to attach to the upper end of choke body 500 at clamp 506.
  • Axial passage 508 has a reduced diameter portion at its upper end; conduit 542 is located inside axial passage 508 and extends through axial passage 508 as a continuation of the reduced diameter portion.
  • the rest of axial passage 508 beyond the reduced diameter portion is of a larger diameter than conduit 542, creating an annulus 520 between the outside surface of conduit 542 and axial passage 508.
  • Conduit 542 extends beyond housing 504 into choke body 500, and past the junction between branch 10 and its perpendicular extension. At this point, the perpendicular extension of branch 10 becomes an outlet 530 of branch 10; this is the same outlet as shown in the Fig. 2 embodiment. Conduit 542 is sealed to the perpendicular extension at seal 532 just below the junction. Outlet 544 and inlet 546 are typically attached to conduits (not shown) which lead to and from processing apparatus, which could be any of the processing apparatus described above with reference to previous embodiments.
  • the diverter assembly 502 can be used to recover fluids from or inject fluids into a well. A method of recovering fluids will now be described.
  • produced fluids come up the production bore 1, enter branch 10 and from there enter annulus 520 between conduit 542 and axial passage 508.
  • the fluids are prevented from going downwards towards outlet 530 by seal 532, so they are forced upwards in annulus 520, exiting annulus 520 via outlet 544.
  • Outlet 544 typically leads to a processing apparatus (which could be any of the ones described earlier, e.g. a pumping or injection apparatus).
  • a processing apparatus which could be any of the ones described earlier, e.g. a pumping or injection apparatus.
  • the fluids Once the fluids have been processed, they are returned through a further conduit (not shown) to inlet 546. From here, the fluids pass through the inside of conduit 542 and exit though outlet 530, from where they are recovered via an export line.
  • Figs 3 and 4 can be used with the flow directions reversed.
  • Fig. 3 and Fig. 4 tree embodiments have the advantage that the diverter assembly can be integrated easily with the existing choke body with minimal intervention in the well; locating a part of the diverter assembly in the choke body need not even involve removing well cap 40.
  • FIG. 5 A further embodiment is shown in Fig. 5 . This is very similar to the Fig. 3 and 4 embodiments, with a choke 540 coupled (e.g. clamped) to the top of choke body 500. Like parts are designated with like reference numerals. Choke 540 is a standard subsea choke.
  • Outlet 544 is coupled via a conduit (not shown) to processing apparatus 550, which is in turn connected to an inlet of choke 540.
  • Choke 540 is a standard choke, having an inner passage with an outlet at its lower end and an inlet 541. The lower end of passage 540 is aligned with inlet 546 of axial passage 508 of housing 504; thus the inner passage of choke 540 and axial passage 508 collectively form one combined axial passage.
  • produced fluids from production bore 1 enter branch 10 and from there enter annulus 520 between conduit 542 and axial passage 508.
  • the fluids are prevented from going downwards towards outlet 530 by seal 532, so they are forced upwards in annulus 520, exiting annulus 520 via outlet 544.
  • Outlet 544 typically leads to a processing apparatus (which could be any of the ones described earlier, e.g. a pumping or injection apparatus).
  • a processing apparatus which could be any of the ones described earlier, e.g. a pumping or injection apparatus.
  • Choke 540 may be opened, or partially opened as desired to control the pressure of the produced fluids.
  • the produced fluids pass through the inner passage of the choke, through conduit 542 and exit through outlet 530, from where they are recovered via an export line.
  • the Fig. 5 embodiment is useful for embodiments which also require a choke in addition to the diverter assembly of Figs. 3 and 4 .
  • the Fig 5 embodiment can be used to inject fluids into a well by reversing the flow paths.
  • Conduit 542 does not necessarily form an extension of axial passage 508.
  • Alternative embodiments could include a conduit which is a separate component to housing 504; this conduit could be sealed to the upper end of axial passage 508 above outlet 544, in a similar way as conduit 542 is sealed at seal 532.
  • Embodiments of the invention can be retrofitted to many different existing designs of manifold, by simply matching the positions and shapes of the hydraulic control channels 3 in the cap, and providing flow diverting channels or connected to the cap which are matched in position (and preferably size) to the production, annulus and other bores in the tree or other manifold.
  • a conventional tree manifold 601 is illustrated having a production bore 602 and an annulus bore 603.
  • the tree has a production wing 620 and associated production wing valve 610.
  • the production wing 620 terminates in a production choke body 630.
  • the production choke body 630 has an interior bore 607 extending therethrough in a direction perpendicular to the production wing 620.
  • the bore 607 of the production choke body is in communication with the production wing 620 so that the choke body 630 forms an extension portion of the production wing 620.
  • the opening at the lower end of the bore 607 comprises an outlet 612.
  • a choke is usually installed in the production choke body 630, but in the tree 601 of the present invention, the choke itself has been removed.
  • the tree 601 also has an annulus wing 621, an annulus wing valve 611, an annulus choke body 631 and an interior bore 609 of the annulus choke body 631 terminating in an inlet 613 at its lower end. There is no choke inside the annulus choke body 631.
  • a first diverter assembly 604 Attached to the production choke body 630 of the production wing 620 is a first diverter assembly 604 in the form of a production insert.
  • the diverter assembly 604 is very similar to the flow diverter assemblies of Figs 3 to 5 .
  • the production insert 604 comprises a substantially cylindrical housing 640, a conduit 642, an inlet 646 and an outlet 644.
  • the housing 640 has a reduced diameter portion 641 at an upper end and an increased diameter portion 643 at a lower end.
  • the conduit 642 has an inner bore 649, and forms an extension of the reduced diameter portion 641.
  • the conduit 642 is longer than the housing 640 so that it extends beyond the end of the housing 640.
  • the space between the outer surface of the conduit 642 and the inner surface of the housing 640 forms an axial passage 647, which ends where the conduit 642 extends out from the housing 640.
  • a connecting lateral passage is provided adjacent to the join of the conduit 642 and the housing 640; the lateral passage is in communication with the axial passage 647 of the housing 640 and terminates in the outlet 644.
  • the lower end of the housing 640 is attached to the upper end of the production choke body 630 at a clamp 648.
  • the conduit 642 is sealingly attached inside the inner bore 607 of the choke body 630 at an annular seal 645.
  • the second diverter assembly 605 is of the same form as the first diverter assembly 604.
  • the components of the second diverter assembly 605 are the same as those of the first diverter assembly 604, including a housing 680 comprising a reduced diameter portion 681 and an enlarged diameter portion 683; a conduit 682 extending from the reduced diameter portion 681 and having a bore 689; an outlet 686; an inlet 684; and an axial passage 687 formed between the enlarged diameter portion 683 of the housing 680 and the conduit 682.
  • a connecting lateral passage is provided adjacent to the join of the conduit 682 and the housing 680; the lateral passage is in communication with the axial passage 687 of the housing 680 and terminates in the inlet 684.
  • the housing 680 is clamped by a clamp 688 on the annulus choke body 631, and the conduit 682 is sealed to the inside of the annulus choke body 631 at seal 685.
  • a conduit 690 connects the outlet 644 of the first diverter assembly 604 to a processing apparatus 700.
  • the processing apparatus 700 comprises bulk water separation equipment, which is adapted to separate water from hydrocarbons.
  • a further conduit 692 connects the inlet 646 of the first diverter assembly 604 to the processing apparatus 700.
  • conduits 694, 696 connect the outlet 686 and the inlet 684 respectively of the second diverter assembly 605 to the processing apparatus 700.
  • the processing apparatus 700 has pumps 820 fitted into the conduits between the separation vessel and the first and second flow diverter assemblies 604, 605.
  • the production bore 602 and the annulus bore 603 extend down into the well from the tree 601, where they are connected to a tubing system 800a, shown in Fig 7 .
  • the tubing system 800a is adapted to allow the simultaneous injection of a first fluid into an injection zone 805 and production of a second fluid from a production zone 804.
  • the tubing system 800a comprises an inner tubing 810 which is located inside an outer tubing 812.
  • the production bore 602 is the inner bore of the inner tubing 810.
  • the inner tubing 810 has perforations 814 in the region of the production zone 804.
  • the outer tubing has perforations 816 in the region of the injection zone 805.
  • a cylindrical plug 801 is provided in the annulus bore 603 which lies between the outer tubing 812 and the inner tubing 810. The plug 801 separates the part of the annulus bore 803 in the region of the injection zone 805 from the rest of the annulus bore 803.
  • the produced fluids (typically a mixture of hydrocarbons and water) enter the inner tubing 810 through the perforations 814 and pass into the production bore 602.
  • the produced fluids then pass through the production wing 620, the axial passage 647, the outlet 644, and the conduit 690 into the processing apparatus 700.
  • the processing apparatus 700 separates the hydrocarbons from the water (and optionally other elements such as sand), e.g. using centrifugal separation.
  • the processing apparatus can comprise any of the types of processing apparatus mentioned in this specification.
  • the separated hydrocarbons flow into the conduit 692, from where they return to the first diverter assembly 604 via the inlet 646.
  • the hydrocarbons then flow down through the conduit 642 and exit the choke body 630 at outlet 612, e.g. for removal to the surface.
  • the water separated from the hydrocarbons by the processing apparatus 700 is diverted through the conduit 696, the axial passage 687, and the annulus wing 611 into the annulus bore 603.
  • the water passes through the perforations 816 in the outer tubing 812 into the injection zone 805.
  • extra fluids can be injected into the well in addition to the separated water. These extra fluids flow into the second diverter assembly 631 via the inlet 613, flow directly through the conduit 682, the conduit 694 and into the processing apparatus 700. These extra fluids are then directed back through the conduit 696 and into the annulus bore 603 as explained above for the path of the separated water.
  • Fig 8 shows an alternative form of tubing system 800b including an inner tubing 820, an outer tubing 822 and an annular seal 821, for use in situations where a production zone 824 is located above an injection zone 825.
  • the inner tubing 820 has perforations 836 in the region of the production zone 824 and the outer tubing 822 has perforations 834 in the region of the injection zone 825.
  • the outer tubing 822 which generally extends round the circumference of the inner tubing 820, is split into a plurality of axial tubes in the region of the production zone 824. This allows fluids from the production zone 824 to pass between the axial tubes and through the perforations 836 in the inner tubing 820 into the production bore 602. From the production bore 602 the fluids pass upwards into the tree as described above. The returned injection fluids in the annulus bore 603 pass through the perforations 834 in the outer tubing 822 into the injection zone 825.
  • the Fig 6 embodiment does not necessarily include any kind of processing apparatus 700.
  • the Fig 6 embodiment may be used to recover fluids and/or inject fluids, either at the same time, or different times.
  • the fluids to be injected do not necessarily have to originate from any recovered fluids; the injected fluids and recovered fluids may instead be two un-related streams of fluids. Therefore, the Fig 6 embodiment does not have to be used for re-injection of recovered fluids; it can additionally be used in methods of injection.
  • the pumps 820 are optional.
  • the tubing system 800a, 800b could be any system that allows both production and injection; the system is not limited to the examples given above.
  • the tubing system could comprise two conduits which are side by side, instead of one inside the other, one of the conduits providing the production bore and the second providing the annulus bore.
  • Figs 9 to 12 illustrate alternative embodiments where the diverter assembly is not inserted within a choke body. These embodiments therefore allow a choke to be used in addition to the diverter assembly.
  • Fig 9 shows a manifold in the form of a tree 900 having a production bore 902, a production wing branch 920, a production wing valve 910, an outlet 912 and a production choke 930.
  • the production choke 930 is a full choke, fitted as standard in many christmas trees, in contrast with the production choke body 630 of the Fig 6 embodiment, from which the actual choke has been removed. In Fig 9 , the production choke 930 is shown in a fully open position.
  • a diverter assembly 904 in the form of a production insert is located in the production wing branch 920 between the production wing valve 910 and the production choke 930.
  • the diverter assembly 904 is the same as the diverter assembly 604 of the Fig 6 embodiment, and like parts are designated here by like numbers, prefixed by "9".
  • the Fig 9 housing 940 is attached to the production wing branch 920 at a clamp 948.
  • the lower end of the conduit 942 is sealed inside the production wing branch 920 at a seal 945.
  • the production wing branch 920 includes a secondary branch 921 which connects the part of the production wing branch 920 adjacent to the diverter assembly 904 with the part of the production wing branch 920 adjacent to the production choke 930.
  • a valve 922 is located in the production wing branch 920 between the diverter assembly 904 and the production choke 930.
  • valve 922 and the seal 945 prevents production fluids from flowing directly from the production bore 902 to the outlet 912. Instead, the production fluids are diverted into the axial annular passage 947 between the conduit 942 and the housing 940. The fluids then exit the outlet 944 into a processing apparatus (examples of which are described above), then re-enter the diverter assembly via the inlet 946, from where they pass through the conduit 942, through the secondary branch 921, the choke 930 and the outlet 912.
  • Fig 10 shows an alternative embodiment of the Fig 9 design, and like parts are denoted by like numbers having a prime.
  • the valve 922 is not needed because the secondary branch 921' continues directly to the production choke 930', instead of rejoining the production wing branch 920'.
  • the diverter assembly 904' is sealed in the production wing branch 920', which prevents fluids from flowing directly along the production wing branch 920', the fluids instead being diverted through the diverter assembly 904'.
  • Fig 11 shows a further embodiment, in which a diverter assembly 1004 is located in an extension 1021 of a production wing branch 1020 beneath a choke 1030.
  • the diverter assembly 1004 is the same as the diverter assemblies of Figs 9 and 10 ; it is merely rotated at 90 degrees with respect to the production wing branch 1020.
  • the diverter assembly 1004 is sealed within the branch extension 1021 at a seal 1045.
  • a valve 1022 is located in the branch extension 1021 below the diverter assembly 1004.
  • the branch extension 1021 comprises a primary passage 1060 and a secondary passage 1061, which departs from the primary passage 1060 on one side of the valve 1022 and rejoins the primary passage 1060 on the other side of the valve 1022.
  • Production fluids pass through the choke 1030 and are diverted by the valve 1022 and the seal 1045 into the axial annular passage 1047 of the diverter assembly 1004 to an outlet 1044. They are then typically processed by a processing apparatus, as described above, and then they are returned to the bore 1049 of the diverter assembly 1004, from where they pass through the secondary passage 1061, back into the primary passage 1060 and out of the outlet 1012.
  • Fig 12 shows a modified version of the Fig 11 apparatus, in which like parts are designated by the same reference number with a prime.
  • the secondary passage 1061' does not rejoin the primary passage 1060'; instead the secondary passage 1061' leads directly to the outlet 1012'.
  • Figs 11 and 12 could be modified for use with a conventional christmas tree by incorporating the diverter assembly 1004, 1004' into further pipework attached to the tree, instead of within an extension branch of the tree.
  • Fig 13 illustrates an alternative method of using the flow diverter assemblies in the recovery of fluids from multiple wells.
  • the flow diverter assemblies can be any of the ones shown in the previously illustrated embodiments, and are not shown in detail in this Figure; for this example, the flow diverter assemblies are the production flow diverter assemblies of Fig 6 .
  • a first diverter assembly 704 is connected to a branch of a first production well A.
  • the diverter assembly 704 comprises a conduit (not shown) sealed within the bore of a choke body to provide a first flow region inside the bore of the conduit and a second flow region in the annulus between the conduit and the bore of the choke body. It is emphasised that the diverter assembly 704 is the same as the diverter assembly 604 of Fig 6 ; however it is being used in a different way, so some outlets of Fig 6 correspond to inlets of Fig 13 and vice versa.
  • the bore of the conduit has an inlet 712 and an outlet 746 (inlet 712 corresponds to outlet 612 of Fig 23 and outlet 746 corresponds to inlet 646 of Fig 6 ).
  • the inlet 712 is in communication with an inlet header 701.
  • the inlet header 701 may contain produced fluids from several other production wells (not shown).
  • the annular passage between the conduit and the choke body is in communication with the production wing branch of the tree of the first well A, and with the outlet 744 (which corresponds to the outlet 644 in Fig 6 ).
  • a second diverter assembly 714 is connected to a branch of a second production well B.
  • the second diverter assembly 714 is the same as the first diverter assembly 704, and is located in a production wing branch in the same way.
  • the bore of the conduit of the second diverter assembly has an inlet 756 (corresponding to the inlet 646 in Fig 6 ) and an outlet 722 (corresponding to the outlet 612 of Fig 6 ).
  • the outlet 722 is connected to an output header 703.
  • the output header 703 is a conduit for conveying the produced fluids to the surface, for example, and may also be fed from several other wells (not shown).
  • the annular passage between the conduit and the inside of the choke body connects the production wing branch to an outlet 754 (which corresponds to the outlet 644 of Fig 6 ).
  • the outlets 746, 744 and 754 are all connected via tubing to the inlet of a pump 750.
  • Pump 750 then passes all of these fluids into the inlet 756 of the second diverter assembly 714.
  • further fluids from other wells are also pumped by pump 750 and passed into the inlet 756.
  • the second diverter assembly 714 functions in the same way as the diverter assembly 604 of the Fig 6 embodiment. Fluids from the production bore of the second well B are diverted by the conduit of the second diverter assembly 714 into the annular passage between the conduit and the inside of the choke body, from where they exit through outlet 754, pass through the pump 750 and are then returned to the bore of the conduit through the inlet 756. The returned fluids pass straight through the bore of the conduit and into the outlet header 703, from where they are recovered.
  • the first diverter assembly 704 functions differently because the produced fluids from the first well 702 are not returned to the first diverter assembly 704 once they leave the outlet 744 of the annulus. Instead, both of the flow regions inside and outside of the conduit have fluid flowing in the same direction. Inside the conduit (the first flow region), fluids flow upwards from the inlet header 701 straight through the conduit to the outlet 746. Outside of the conduit (the second flow region), fluids flow upwards from the production bore of the first well 702 to the outlet 744.
  • Both streams of upwardly flowing fluids combine with fluids from the outlet 754 of the second diverter assembly 714, from where they enter the pump 750, pass through the second diverter assembly into the outlet header 703, as described above.
  • the tree 601 is a conventional tree but the invention can also be used with horizontal trees.
  • One or both of the flow diverter assemblies of the Fig 6 embodiment could be located within the production bore and/or the annulus bore, instead of within the production and annular choke bodies.
  • the processing apparatus 700 could be one or more of a wide variety of equipment.
  • the processing apparatus 700 could comprise any of the types of equipment described above.
  • Fig 14 shows a further diverter assembly 1110 (not an embodiment of the invention, but useful for understanding it) which is attached to a choke body 1112, which is located in the production wing branch 1114 of a christmas tree 1116.
  • the production wing branch 1114 has an outlet 1118, which is located adjacent to the choke body 1112.
  • the diverter assembly 1110 is attached to the choke body 1112 by a clamp 1119.
  • a first valve V1 is located in the central bore of the christmas tree and a second valve V2 is located in the production wing branch 1114.
  • the choke body 1112 is a standard subsea choke body from which the original choke has been removed.
  • the choke body 1112 has a bore which is in fluid communication with the production wing branch 1114.
  • the upper end of the bore of the choke body 1112 terminates in an aperture in the upper surface of the choke body 1112.
  • the lower end of the bore of the choke body communicates with the bore of the production wing branch 1114 and the outlet 1118.
  • the diverter assembly 1110 has a cylindrical housing 1120, which has an interior axial passage 1122.
  • the lower end of the axial passage 1122 is open; i.e. it terminates in an aperture.
  • the upper end of the axial passage 1122 is closed, and a lateral passage 1126 extends from the upper end of the axial passage 1122 to an outlet 1124 in the side wall of the cylindrical housing 1120.
  • the diverter assembly 1110 has a stem 1128 which extends from the upper closed end of the axial passage 1122, down through the axial passage 1122, where it terminates in a plug 1130.
  • the stem 1128 is longer than the housing 1120, so the lower end of the stem 1128 extends beyond the lower end of the housing 1120.
  • the plug 1130 is shaped to engage a seat in the choke body 1112, so that it blocks the part of the production wing branch 1114 leading to the outlet 1118. The plug therefore prevents fluids from the production wing branch 1114 or from the choke body 1112 from exiting via the outlet 1118.
  • the plug is optionally provided with a seal, to ensure that no leaking of fluids can take place.
  • a choke is typically present inside the choke body 1112 and the outlet 1118 is typically connected to an outlet conduit, which conveys the produced fluids away e.g. to the surface.
  • Produced fluids flow through the bore of the christmas tree 1116, through valves V1 and V2, through the production wing branch 1114, and out of outlet 1118 via the choke.
  • the diverter assembly 1110 can be retrofitted to a well by closing one or both of the valves V1 and V2 of the christmas tree 1116. This prevents any fluids leaking into the ocean whilst the diverter assembly 1110 is being fitted.
  • the choke (if present) is removed from the choke body 1112 by a standard removal procedure known in the art.
  • the diverter assembly 1110 is then clamped onto the top of the choke body 1112 by the clamp 1119 so that the stem 1128 extends into the bore of the choke body 1112 and the plug 1130 engages a seat in the choke body 1112 to block off the outlet 1118.
  • Further pipework (not shown) is then attached to the outlet 1124 of the diverter assembly 1110. This further pipework can now be used to divert the fluids to any desired location.
  • the fluids may be then diverted to a processing apparatus, or a component of the produced fluids may be diverted into another well bore to be used as injection fluids.
  • valves V1 and V2 are now re-opened which allows the produced fluids to pass into the production wing branch 1114 and into the choke body 1112, from where they are diverted from their former route to the outlet 1118 by the plug 1130, and are instead diverted through the diverter assembly 1110, out of the outlet 1124 and into the pipework attached to the outlet 1124.
  • Fig 15 shows an alternative diverter assembly 1110' (not an embodiment of the invention, but useful for understanding it) attached to the christmas tree 1116, and like parts will be designated by like numbers having a prime.
  • the christmas tree 1116 is the same christmas tree 1116 as shown in Fig 14 , so these reference numbers are not primed.
  • the housing 1120' in the diverter assembly 1110' is cylindrical with an axial passage 1122'. However, in this diverter assembly, there is no lateral passage, and the upper end of the axial passage 1122' terminates in an aperture 1130' in the upper end of the housing 1120', so that the upper end of the housing 1120' is open. Thus, the axial passage 1122' extends all of the way through the housing 1120' between its lower and upper ends.
  • the aperture 1130' can be connected to external pipework (not shown).
  • Fig 16 shows a further alternative diverter assembly (not an embodiment of the invention, but useful for understanding it) 1110", and like parts are designated by like numbers having a double prime.
  • This Figure is cut off after the valve V2; the rest of the christmas tree is the same as that of the previous two diverter assemblies. Again, the christmas tree of this diverter assembly is the same as those of the previous two, and so these reference numbers are not primed.
  • the housing 1120" of the Fig 16 diverter assembly is substantially the same as the housing 1120' of the Fig 15 version.
  • the housing 1120" is cylindrical and has an axial passage 1122" extending therethrough between its lower and upper ends, both of which are open.
  • the aperture 1130" can be connected to external pipework (not shown).
  • the housing 1120" is provided with an extension portion in the form of a conduit 1132", which extends from near the upper end of the housing 1120", down through the axial passage 1122" to a point beyond the end of the housing 1120".
  • the conduit 1132" is therefore internal to the housing 1120", and defines an annulus 1134" between the conduit 1132" and the housing 1120".
  • the lower end of the conduit 1132" is adapted to fit inside a recess in the choke body 1112, and is provided with a seal 1136, so that it can seal within this recess, and the length of conduit 1132" is determined accordingly.
  • the conduit 1132" divides the space within the choke body 1112 and the diverter assembly 1110" into two distinct and separate regions.
  • a first region is defined by the bore of the conduit 1132" and the part of the production wing bore 1114 beneath the choke body 1112 leading to the outlet 1118.
  • the second region is defined by the annulus between the conduit 1132" and the housing 1120"/the choke body 1112.
  • the conduit 1132" forms the boundary between these two regions, and the seal 1136 ensures that there is no fluid communication between these two regions, so that they are completely separate.
  • the Fig 16 diverter assembly is similar to the embodiments of Figs 3 and 4 , with the difference that the Fig 16 annulus is closed at its upper end.
  • the diverter assemblies of Figs 15 and 16 may function in substantially the same way.
  • the valves V1 and V2 are closed to allow the choke to be removed from the choke body 1112 and the diverter assembly 1110', 1110" to be clamped on to the choke body 1112, as described above with reference to Fig 14 . Further pipework leading to desired equipment is then attached to the aperture 1130', 1130".
  • the diverter assembly 1110', 1110" can then be used to divert fluids in either direction therethrough between the apertures 1118 and 1130', 1130".
  • Fig 15 diverter assembly there is the option to divert fluids into or from the well, if the valves V1, V2 are open, and the option to exclude these fluids by closing at least one of these valves.
  • Figs 15 and 16 can be used to recover fluids from or inject fluids into a well. Any of the embodiments shown attached to a production choke body may alternatively be attached to an annulus choke body of an annulus wing branch leading to an annulus bore of a well.
  • Fig 16 no fluids can pass directly between the production bore and the aperture 1118 via the wing branch 1114, due to the seal 1136.
  • This arrangement may optionally function as a pipe connector for a flowline not connected to the well.
  • the Fig 16 arrangement could simply be used to connect two pipes together.
  • fluids flowing through the axial passage 1132" may be directed into, or may come from, the well bore via a bypass line.
  • An example of such an arrangement is shown in Fig 17 .
  • Fig 17 shows the Fig 16 apparatus attached to the choke body 1112 of the tree 1116.
  • the tree 1116 has a cap 1140, which has an axial passage 1142 extending therethrough.
  • the axial passage 1142 is aligned with and connects directly to the production bore of the tree 1116.
  • a first conduit 1146 connects the axial passage 1142 to a processing apparatus 1148.
  • the processing apparatus 1148 may comprise any of the types of processing apparatus described in this specification.
  • a second conduit 1150 connects the processing apparatus 1148 to the aperture 1130" in the housing 1120".
  • Valve V2 is shut and valve V1 is open.
  • the fluids travel up through the production bore of the tree; they cannot pass into through the wing branch 1114 because of the V2 valve which is closed, and they are instead diverted into the cap 1140.
  • the fluids pass through the conduit 1146, through the processing apparatus 1148 and they are then conveyed to the axial passage 1122' by the conduit 1150.
  • the fluids travel down the axial passage 1122' to the aperture 1118 and are recovered therefrom via a standard outlet line connected to this aperture.
  • the direction of flow is reversed, so that the fluids to be injected are passed into the aperture 1118 and are then conveyed through the axial passage 1122', the conduit 1150, the processing apparatus 1148, the conduit 1146, the cap 1140 and from the cap directly into the production bore of the tree and the well bore.
  • the first conduit 1146 could instead connect to an annulus branch and an annulus bore; a crossover port could then connect the annulus bore to the production bore, if desired. Any opening into the tree manifold could be used.
  • the processing apparatus could comprise any of the types described in this specification, or could alternatively be omitted completely.
  • the uses of the invention are very wide ranging.
  • the further pipework attached to the diverter assembly could lead to an outlet header, an inlet header, a further well, or some processing apparatus (not shown). Many of these processes may never have been envisaged when the christmas tree was originally installed, and the invention provides the advantage of being able to adapt these existing trees in a low cost way while reducing the risk of leaks.
  • the diverter assembly could be attached to an annulus choke body, instead of to a production choke body.
  • Fig 13 the methods shown in Fig 13 were described with reference to the Fig 6 embodiment, but these could be accomplished with any of the embodiments providing two separate flowpaths. With modifications to the method of Fig 13 , so that fluids from the well A are only required to flow to the outlet header 703, without any addition of fluids from the inlet header 701, the embodiments only providing a single flowpath ( Figs 14 and 15 ) could also be used. Alternatively, if fluids were only needed to be diverted between the inlet header 701 and the outlet header 703, without the addition of any fluids from well A, the Fig 16 embodiment could also be used. Similar considerations apply to well B.
  • Recovering fluids from a first well and injecting at least a portion of these fluids into a second well could likewise be achieved with any of the two-flowpath embodiments of Figs 3-5 and 9-12 .
  • the single flowpath embodiments of Figs 14 and Figs 15 could be used for the injection well 330.
  • Such an embodiment is shown in Fig 18 , which shows a first recovery well A and a second injection well B.
  • Wells A and B each have a tree and a diverter assembly according to Fig 14 . Fluids are recovered from well A via the diverter assembly; the fluids pass into a conduit C and enter a processing apparatus P.
  • the processing apparatus includes a separating apparatus and a fluid riser R.
  • the processing apparatus separates hydrocarbons from the recovered fluids and sends these into the fluid riser R for recovery to the surface via this riser.
  • the remaining fluids are diverted into conduit D which leads to the diverter assembly of the injection well B, and from there, the fluids pass into the well bore.
  • This embodiment allows diversion of fluids whilst bypassing the export line which is normally connected to outlets 1118.
  • single flowpath embodiments could also be used for the production well.
  • This method can therefore be achieved with a diverter assembly located in the production/annulus bore or in a wing branch, and with most of the embodiments of diverter assembly described in this specification.
  • Fig 6 in which recovery and injection occur in the same well, could be achieved with the flow diverter of Fig 2 (so that at least one of the flow diverters is located in the production bore/annulus bore).
  • a first diverter assembly could be located in the production bore and a second diverter assembly could be attached to the annulus choke, for example.
  • Further alternative embodiments may have a diverter assembly in the annulus bore, similar to the embodiment of Fig 2 in the production bore.
  • Fig 6 in which recovery and injection occur in the same well, could also be achieved with any of the other diverter assemblies described in the application, including the diverter assemblies which do not provide two separate flowpaths.
  • An example of one such modified method is shown in Fig 19 . This shows the same tree as Fig 6 , used with two Fig 14 diverter assemblies.
  • this modified method none of the fluids recovered from the first diverter assembly 640 connected to the production bore 602 are returned to the first diverter assembly 640. Instead, fluids are recovered from the production bore, are diverted through the first diverter assembly 640 into a conduit 690, which leads to a processing apparatus 700.
  • the processing apparatus 700 could be any of the ones described in this application.
  • the processing apparatus 700 including both a separating apparatus and a fluid riser R to the surface.
  • the apparatus 700 separates hydrocarbons from the rest of the produced fluids, and the hydrocarbons are recovered to the surface via the fluid riser R, whilst the rest of the fluids are returned to the tree via conduit 696. These fluids are injected into the annulus bore via the second diverter assembly 680.
  • the methods of recovery and injection are not limited to methods which include the return of some of the recovered fluids to the diverter assembly used in the recovery, or return of the fluids to a second portion of a first flowpath.
  • All of the diverter assemblies shown and described can be used for both recovery of fluids and injection of fluids by reversing the flow direction.
  • Figs 14 to 17 could be connected to other parts of the wing branch, and are not necessarily attached to a choke body.
  • these arrangements could be located in series with a choke, at a different point in the wing branch, such as shown in the embodiments of Figs 9 to 12 .

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  • Geology (AREA)
  • Life Sciences & Earth Sciences (AREA)
  • Engineering & Computer Science (AREA)
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  • Geochemistry & Mineralogy (AREA)
  • Fluid Mechanics (AREA)
  • Environmental & Geological Engineering (AREA)
  • General Life Sciences & Earth Sciences (AREA)
  • Physics & Mathematics (AREA)
  • Physical Or Chemical Processes And Apparatus (AREA)
  • Pipeline Systems (AREA)
  • Consolidation Of Soil By Introduction Of Solidifying Substances Into Soil (AREA)
  • Separation Using Semi-Permeable Membranes (AREA)
  • Multiple-Way Valves (AREA)
  • Jet Pumps And Other Pumps (AREA)
  • Quick-Acting Or Multi-Walled Pipe Joints (AREA)

Claims (7)

  1. Eine Anordnung für ein Öl- oder Gasbohrloch, beinhaltend:
    einen Eruptionskreuzkörper mit einer Förderbohrung (602);
    eine seitliche Abzweigung (620), die mit der Förderbohrung (602) in Verbindung steht;
    einen auf der seitlichen Abzweigung (620) angeordneten Drosselkörper (630);
    gekennzeichnet durch:
    eine Diverteranordnung (604) mit einem Durchgang (647), der mit der seitlichen Abzweigung (620) in Verbindung steht, und einer Leitung (642) mit einem inneren Durchgang (649), der mit einem Auslass (612) in Verbindung steht; und
    eine Verarbeitungsvorrichtung (700), die mit dem Durchgang (647) und dem inneren Durchgang (649) in Verbindung steht.
  2. Anordnung gemäß Anspruch 1, wobei die seitliche Abzweigung (920) ein Ventil (610) zum Regeln der Strömung mit dem Auslass (612) umfasst.
  3. Anordnung gemäß Anspruch 1, wobei der Eruptionskreuzkörper eine Ringraumbohrung (603) und einen Ringraumflügel (621) aufweist, wobei der Ringraumflügel (621) einen Ringraumdrosselkörper (631) und einen Einlass aufweist, wobei die Verarbeitungsvorrichtung (700) eine Leitung (690) aufweist, die mit dem Durchgang (647) in Verbindung steht, der sich durch den Diverter (604) erstreckt und mit der seitlichen Abzweigung (620) in Verbindung steht, und eine Leitung (692), die mit dem inneren Durchgang (649) in Verbindung steht, der mit dem Auslass (612) in Verbindung steht; und
    wobei die Verarbeitungsvorrichtung (700) eine Leitung (694) aufweist, die mit einer Leitung (689) in einer an dem Ringraumdrosselkörper (631) angeordneten und mit einem Einlass (613) in Verbindung stehenden Ringraumdiverteranordnung (605) und einer mit einem Ringraumdurchgang (687) und mit dem Ringraumflügel (621) in Verbindung stehenden Leitung (696) in Verbindung steht.
  4. Anordnung gemäß Anspruch 3, wobei die Flüssigkeit entweder zur gleichen Zeit oder zu unterschiedlichen Zeiten durch die Ringraumbohrung (603) oder die Förderbohrung (602) unter Verwendung der Verarbeitungsvorrichtung (700) aus dem Bohrloch wiedergewonnen und/oder in dieses eingepresst werden kann.
  5. Anordnung gemäß Anspruch 3 oder Anspruch 4, wobei der Eruptionskreuzkörper ein sich von der Förderbohrung zu einer Förderzone (804) erstreckendes Fördersteigrohr (800) und ein äußeres Steigrohr (812) um das Fördersteigrohr (800), das einen Ringraum (603) bildet, der sich von der Ringraumbohrung zu einer Einpresszone (805) erstreckt, umfasst.
  6. Anordnung gemäß einem der Ansprüche 3-5, ferner umfassend Abdichtmittel (801) zum Abdichten des Ringraums (603), um die Förderzone (804) von der Einpresszone (805) zu trennen.
  7. Anordnung gemäß Anspruch 1, wobei das Bohrloch ein Förderbohrloch (A) ist, wobei die Diverteranordnung (604, 704) einen Auslass (644, 744) für Förderflüssigkeiten aufweist;
    einen Einlasssammler (701), der mit einem Einlass (712) der seitlichen Abzweigung (620) in Verbindung steht und der Einlass (712) mit einem Auslass (646, 746) der Diverteranordnung (704) in Verbindung steht;
    Leitungen, die sich von den Auslässen (644, 744, 646, 746) zu einem Steigrohr erstrecken, das mit einer Pumpe (750) in Verbindung steht;
    eine weitere Förderbohrung (B), die ein Eruptionskreuz mit einer seitlichen Abzweigung aufweist;
    eine Diverteranordnung (604, 714), die an der seitlichen Abzweigung auf dem Eruptionskreuz angeordnet ist und einen Auslass (754) und einen Einlass (756) aufweist;
    einen Ausgangssammler (703), der mit einem Einlass (722) der Diverteranordnung (714) und dem Einlass (722) in Verbindung steht, welcher mit dem Auslass (754) in Verbindung steht; und
    der Auslass (754) mit einem Einlass der Pumpe (750) in Verbindung steht und der Einlass (756) mit einem Auslass der Pumpe (750) in Verbindung steht.
EP10013192.9A 2003-05-31 2004-06-01 Vorrichtung und Verfahren zur Rückgewinnung der unterirdischen Flüssigkeiten und/oder Injizieren von Flüssigkeiten und/oder Injizieren von Flüssigkeiten in einem Bohrloch Expired - Lifetime EP2287438B1 (de)

Applications Claiming Priority (8)

Application Number Priority Date Filing Date Title
GBGB0312543.2A GB0312543D0 (en) 2003-05-31 2003-05-31 Method and apparatus
US10/651,703 US7111687B2 (en) 1999-05-14 2003-08-29 Recovery of production fluids from an oil or gas well
US54872704P 2004-02-26 2004-02-26
GBGB0405471.4A GB0405471D0 (en) 2004-03-11 2004-03-11 Apparatus and method for recovering fluids from a well
GBGB0405454.0A GB0405454D0 (en) 2004-03-11 2004-03-11 Apparatus and method for recovering fluids from a well
EP04735596A EP1639230B1 (de) 2003-05-31 2004-06-01 Vorrichtung und verfahren zur rückgewinnung der unterirdischen flüssigkeiten und/oder injizieren von flüssigkeiten in einem bohrloch
EP08162149A EP1990505B1 (de) 2003-05-31 2004-06-01 Vorrichtung und Verfahren zur Rückgewinnung von Flüssigkeiten aus einem Bohrloch und/oder zum Einspritzen von Flüssigkeiten in ein Bohrloch
EP10161116.8A EP2216502B1 (de) 2003-05-31 2004-06-01 Vorrichtung und Verfahren zur Rückgewinnung der unterirdischen Flüssigkeiten und/oder Injizieren von Flüssigkeiten in einem Bohrloch

Related Parent Applications (7)

Application Number Title Priority Date Filing Date
EP08162149A Division EP1990505B1 (de) 2003-05-31 2004-06-01 Vorrichtung und Verfahren zur Rückgewinnung von Flüssigkeiten aus einem Bohrloch und/oder zum Einspritzen von Flüssigkeiten in ein Bohrloch
EP04735596.1 Division 2004-06-01
EP10161116.8A Division-Into EP2216502B1 (de) 2003-05-31 2004-06-01 Vorrichtung und Verfahren zur Rückgewinnung der unterirdischen Flüssigkeiten und/oder Injizieren von Flüssigkeiten in einem Bohrloch
EP10161116.8A Division EP2216502B1 (de) 2003-05-31 2004-06-01 Vorrichtung und Verfahren zur Rückgewinnung der unterirdischen Flüssigkeiten und/oder Injizieren von Flüssigkeiten in einem Bohrloch
EP04735596A Division EP1639230B1 (de) 2003-05-31 2004-06-01 Vorrichtung und verfahren zur rückgewinnung der unterirdischen flüssigkeiten und/oder injizieren von flüssigkeiten in einem bohrloch
EP08162149.2 Division 2008-08-11
EP10161116.8 Division 2010-04-27

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EP2287438A1 EP2287438A1 (de) 2011-02-23
EP2287438B1 true EP2287438B1 (de) 2017-10-04

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EP10161120.0A Expired - Lifetime EP2221450B1 (de) 2003-05-31 2004-06-01 Vorrichtung und Verfahren zur Rückgewinnung von Flüssigkeiten aus einem Bohrloch und/oder zum Einspritzen von Flüssigkeiten in ein Bohrloch
EP10167182.4A Expired - Lifetime EP2233686B1 (de) 2003-05-31 2004-06-01 Vorrichtung und Verfahren zur Rückgewinnung von Flüssigkeiten aus einem Bohrloch und/oder zum Einspritzen von Flüssigkeiten in ein Bohrloch
EP10013192.9A Expired - Lifetime EP2287438B1 (de) 2003-05-31 2004-06-01 Vorrichtung und Verfahren zur Rückgewinnung der unterirdischen Flüssigkeiten und/oder Injizieren von Flüssigkeiten und/oder Injizieren von Flüssigkeiten in einem Bohrloch
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EP04735596A Expired - Lifetime EP1639230B1 (de) 2003-05-31 2004-06-01 Vorrichtung und verfahren zur rückgewinnung der unterirdischen flüssigkeiten und/oder injizieren von flüssigkeiten in einem bohrloch
EP17186597.5A Expired - Lifetime EP3272995B1 (de) 2003-05-31 2004-06-01 Vorrichtung und verfahren zur rückgewinnung von fluiden aus einem bohrloch und/oder zum einspritzen von fluiden in ein bohrloch
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EP10185795.1A Expired - Lifetime EP2282004B1 (de) 2003-05-31 2004-06-01 Vorrichtung und Verfahren zur Rückgewinnung der unterirdischen Flüssigkeiten und/oder Injizieren von Flüssigkeiten in einem Bohrloch
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US8281864B2 (en) 2012-10-09
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US20090301727A1 (en) 2009-12-10
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US20120175103A1 (en) 2012-07-12
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US8622138B2 (en) 2014-01-07
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US7992633B2 (en) 2011-08-09
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US8733436B2 (en) 2014-05-27
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US20110290500A1 (en) 2011-12-01
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